In drilling a borehole in the earth, such as for the recovery of hydrocarbons or minerals or for other applications, it is conventional practice to connect a drill bit on the lower end of an assembly of drill pipe sections which are connected end-to-end so as to form a "drill string." The drill string is rotated by apparatus that is positioned on a drilling platform located at the surface of the borehole. Such apparatus turns the bit and advances it downwardly, causing the bit to cut through the formation material by either abrasion, fracturing, or shearing action, or through a combination of all such cutting methods. While the bit is rotated, drilling fluid is pumped through the drill string and directed out of the drill bit through nozzles that are positioned in the bit face. The drilling fluid is provided to cool the bit and to flush cuttings away from the cutting structure of the bit. The drilling fluid forces the cuttings from the bottom of the borehole and carries them to the surface through the annulus that is formed between the drill string and the borehole.
Many different types of drill bits and bit cutting structures have been developed and found useful in various drilling applications. Such bits include fixed cutter bits and roller cone bits. The types of cutting structures include steel teeth, tungsten carbide inserts ("TCI"), polycrystalline diamond compacts ("PDC's"), and natural diamond. The selection of the appropriate bit and cutting structure for a given application depends upon many factors. One of the most important of these factors is the type of formation that is to be drilled, and more particularly, the hardness of the formation that will be encountered. Another important consideration is the range of hardnesses that will be encountered when drilling through different layers or strata of formation material.
Depending upon formation hardness, certain combinations of the above-described bit types and cutting structures will work more efficiently and effectively against the formation than others. For example, a milled tooth roller cone bit generally drills relatively quickly and effectively in soft formations, such as those typically encountered at shallow depths. By contrast, milled tooth roller cone bits are relatively ineffective in hard rock formations as may be encountered at greater depths. For drilling through such hard formations, roller cone bits having TCI cutting structures have proven to be very effective. For certain hard formations, fixed cutter bits having a natural diamond cutting structure provide the best combination of penetration rate and durability. In formations of soft and medium hardness, fixed cutter bits having a PDC cutting structure are commonly employed.
Drilling a borehole for the recovery of hydrocarbons or minerals is typically very expensive due to the high cost of the equipment and personnel that are required to safely and effectively drill to the desired depth and location. The total drilling cost is proportional to the length of time it takes to drill the borehole. The drilling time, in turn, is greatly affected by the rate of penetration (ROP) of the drill bit and the number of times the drill bit must be changed in the course of drilling. A bit may need to be changed because of wear or breakage, or to substitute a bit that is better able to penetrate a particular formation. Each time the bit is changed, the entire drill string--which may be miles long--must be retrieved from the borehole, section by section. Once the drill string has been retrieved and the new bit installed, the bit must be lowered to the bottom of the borehole on the drill string which must be reconstructed again, section by section. As is thus obvious, this process, known as a "trip" of the drill string, requires considerable time, effort and expense. Accordingly, because drilling cost is so time dependent, it is always desirable to employ drill bits that will drill faster and longer and that are usable over a wider range of differing formation hardnesses.
The length of time that a drill bit may be employed before the drill string must be tripped and the bit changed depends upon the bit's rate of penetration ("ROP"), as well as its durability, that is, its ability to maintain a high or acceptable ROP. In recent years, the PDC bit has become an industry standard for cutting formations of soft and medium hardnesses. The cutter elements used in such bits are formed of extremely hard materials and include a layer of polycrystalline diamond material. In the typical PDC bit, each cutter element or assembly comprises an elongate and generally cylindrical support member which is received and secured in a pocket formed in the surface of the bit body. A disk or tablet-shaped, performed cutting element having a thin, hard cutting layer of polycrystalline diamond is bonded to the exposed end of the support member, which is typically formed of tungsten carbide.
A once common arrangement of the PDC cutting elements was to place them in a spiral configuration along the bit face. More specifically, the cutter elements were placed at selected radial positions with respect to the central axis of the bit, with each element being placed at a slightly more remote radial position than the preceding element. So positioned, the path of all but the center-most elements partly overlapped the path of travel of a preceding cutter element as the bit was rotated.
Although the spiral arrangement was once widely employed, this arrangement of cutter elements was found to wear in a manner to cause the bit to assume a cutting profile that presented a relatively flat and single continuous cutting edge from one element to the next. Not only did this decrease the ROP that the bit could provide, it but also increased the likelihood of bit vibration or instability which can lead to premature wearing or destruction of the cutting elements and a loss of penetration rate. All of these conditions are undesirable. A low ROP increases drilling time and cost, and may necessitate a costly trip of the drill string in order to replace the dull bit with a new bit. Excessive bit vibration will itself dull or damage the bit to an extent that a premature trip of the drill string becomes necessary.
Although PDC bits are widely used, less than desirable performance has sometimes been encountered when drilling through a region of soft shale, usually at great depths or when using drilling fluids having a high specific density (commonly referred to as "heavy" muds). Generally, the poor performance has been noted when drilling in shale formations where the well pressure is substantially high. In such conditions, the ROP of the bit will many times drop dramatically from a desirable ROP to an uneconomical value.
Various theories have been presented in an attempt to explain this phenomena with the hope that, with a better understanding of the drilling conditions, a bit can be designed that will not exhibit the dramatic drop in ROP when such a formation is encountered. One explanation is that the shale in these conditions exhibits a plastic like quality such that the cutter elements depress or deform the formation, but are unable to effectively shear cuttings away from the surrounding material. Another theory holds that the cutter elements are successful in shearing cuttings from the surrounding formation, but due to the nature of the material and current bit designs, the cuttings are not effectively removed from the borehole bottom but instead stick together on the bit face. This phenomena, commonly known as "balling," lessens the ability of the bit to penetrate into the formation, and also impedes the flow of drilling fluid from the nozzles, flow that is intended to wash across the bit face and remove such cuttings. Without regard to the various conditions which cause the phenomena, the drastically reduced ROP is a significant problem leading to increased drilling costs and, ultimately, an increase to the consumer in the cost of petroleum products.
Presently, when encountering such plastic shale formations, it has been customary to increase the "weight on bit" (WOB) in an effort to increase the now-reduced ROP. Unfortunately, increasing WOB causes the cuttings which have not yet been successfully cleaned away from the bit face to become compacted on the borehole bottom. These compacted cuttings tend to support the added WOB and lessen the ability of the bit to shear uncut formation material. Further, drilling with an increased or high WOB has other serious consequences and is avoided whenever possible. Increasing the WOB is accomplished by installing additional heavy drill collars on the drill string. This additional weight increases the stress and strain on all drill string components, causes stabilizers to wear more quickly and to work less efficiently, and increases the hydraulic pressure drop in the drill string, requiring the use of higher capacity (and typically higher cost) pumps for circulating the drilling fluid. High WOB also has a detrimental effect on drill string mechanics.
Thus, there remains a need in the art for a fixed cutter drill bit having an improved design that will permit the bit to drill effectively with economical ROPs in plastic shale formations. More specifically, there is a need for a PDC bit which can drill in such shale formations with an aggressive profile so as to maintain a superior ROP while progressing through the formation of the plastic shale so as to lower the drilling costs presently experienced in the industry. Such a bit should provide the desired ROP without having to employ substantial additional WOB and suffering from the costly consequences which arise from drilling with such extra weight. Ideally, the bit would also include a cutting structure that would provide increased durabilty once the bit has advanced through the plastic shale formation and encountered harder and/or more abrasive formations.